This invention relates to wellbore fluids, including drilling fluids, completion fluids, workover fluids, packer fluids, that is, all of those fluids which are employed over the course of the life of a well, usually drilled for the production of oil or gas. It can be used for wells drilled for injection or production of fluids into or from subterranean formations.
Generally, wellbore fluids will be either clay-based or brines, which are clay-free. These two classes are exclusive, that is, clay-based drilling fluids are not brines. A wellbore fluid can perform any one or more of a number of functions. For example, the drilling fluid will generally provide a cooling medium for the rotary bit used to drill the wells and a means to carry off the drilled particles. Since great volumes of drilling fluid are required for these purposes, the fluids generally have been based on water. Water alone, however, does not have the capacity to carry the drilled particles from the borehole to the surface or along perform any number of other requirements. Thus, other components are required.
The drilling muds used in oil wells, gas wells and similar boreholes are generally aqueous solutions containing suspended solids and additives designed to impart the required density, viscosity and thixotropic properties to the mud. When such a mud comes into contact with porous subsurface strata, the liquid constitutents tend to filter into the strata. The solids accumulate to form a filter cake on the borehole wall. It is preferable that the quantity of liquid thus lost to the surrounding formation and the thickness of the filter cake formed be held to a minimum. The loss of large quantities of liquid and the formation of a thick cake adversely affects critical properties of the mud and formation, contaminates fluids present in the formation, leads to the hydration of clays and shales, complicates the interpretation of logs, obscures oil and gas sands that might otherwise be detected, promotes sticking of the drill string in the borehole, and reduces permeability of producing or injection formations. Similar problems are encountered with workover fluids, completion fluids, fracturing fluids and related compositions. Additives are often employed to minimize these and related difficulties encountered with muds in similar positions.
A variety of organic gums and polymers have been used, or proposed for use, as additives in drilling muds and related fluids. These include starch, carboxymethyl cellulose, gum tragacanth, gum karaya, gum ghatti, guar gum, Irish moss, acrylonitrile polymers, phenol-formaldehyde condensation products, Viscoba gum, and the like. Though useful in specific instances, none of these materials has been found wholly satisfactory.
In the drilling fluid class, clay-based fluids have for years preempted the field, because of the traditional and widely held theory in the field that the viscisity suitable for creating a particle carrying capacity in the drilling fluid could be achieved only with a drilling fluid having thixotropic properties, that is, the viscosity must be supplied by a material that will have sufficient gel strength to prevent suspended particles from separating from the drilling fluid when agitation of the drilling fluid has ceased, for example, in a holding tank at the surface.
In order to obtain the requisite thixotropy or gel strength, hydratable clay or colloidal clay bodies such as bentonite or fuller's earth have been employed. As a result, the drilling fluids are usually referred to as "muds". The use of clay-based drilling muds has provided the means of meeting two of the basic requirements of drilling fluids, i.e., cooling and particle removal.
Non-argillaceous (clay free) wellbore fluids based on viscosifiers have been developed, which overcome the problem with the clay-based fluids, of high fluid loss values and accumulation of the mud filter cake on the borehole wall, such as a brine containing a viscosifying amount of magnesia-stabilized hydroxyethylcellulose described in U.S. Pat. No. 3,988,246. The clay-free brines have the advantage of containing hydration-inhibiting materials such as potassium chloride, calcium chloride or the like. Quite apparently any solid particulate material would be easily separated from the brine solution since it is not hydrated. Thus, the properties of the brine are not changed by solid particulate matter from the wellbore.
In addition to soluble brine salts and modified starches, wellbore fluids can contain other conventional wellbore additives, such as hydroxyethylcellulose, gums, lignosulfonate salts such as calcium or chromium lignosulfonates, emulsifiers, weighting agents, calcium carbonate, magnesia and other agents. It is understood that not all of these possible constituents will be present in any one wellbore fluid but their selection and use will be governed by other constituents and the use for which the wellbore fluid is intended and is well known to those skilled in the art. Such components may be added to a dry mix package as well.
A common problem for both clay-based and clay-free brine wellbore fluids is water loss. A number of approaches have been employed to prevent water loss into the penetrated formation. For example, lignosulfonate salts are frequently employed for that purpose. Also oil has been employed as a water loss control agent.
Although starches have been employed in clay-based and brine fluids, they have generally not been successful in substantially reducing water loss in the drilling fluid, while at the same time maintaining low amounts of undesirable crosslinking after the mud is compounded, desirable flow characteristics and low shale sensitivity. Shale sensitivity is characterized by dissolution of shale into the drilling solution resulting in a higher drilling fluid viscosity. A drilling fluid with low shale sensitivity is able to tolerate a large amount of drilling solids, whereas a fluid with high shale sensitivity cannot.
Many times in drilling a well, it is necessary to lower the fluid loss and yet maintain desirable flow characteristics to the mud system. When common additivies such as bentonite will no longer give the properties needed, it has been common practice to add small amounts of some polymers in order to lower the water loss of the mud. This has resulted in a number of problems such as, for example: (1) solids too high to accept the polymers presently available on the market, (2) some polymers used were directed almost entirely to controlling flow characteristics without maintaining water loss control, (3) polymers used resulted in adequate water loss control but at the expense of desirable flow characteristics, (4) rheological properties of muds too sensitive to small additions of the available polymers, (5) available polymers were not effective in both fresh and salt water, (6) polymers would not tolerate solids buildup, (7) down hole formations encountered or surface addition of additivies (such as some corrosion inhibitors) radically altered the mud properties, or caused the mud system to gel.
Starch additives have previously been used to lower water loss, as described in U.S. Pat. Nos. 3,243,000; 3,988,246; 3,993,570; and 4,090,968, however, no starch additive has heretofore been successful in reducing water loss to extremely low values, while also maintaining low amounts of undesirable crosslinking in the mud after being compounded, desirable flow characteristics, and low shale sensitivity.
It is a feature of the present invention to provide an aqueous thixotropic, stable wellbore fluid which does not damage the formation having improved water loss control, low amounts of undesirable crosslinking, desirable flow characteristics, and low sensitivity to shale.
It is a further feature of the present invention to provide a water loss control additive which is effective for both clay containing and clay-free and fresh water-based and brine-based drilling fluids.
It is an advantage of the present invention that the additive package of this invention results in lower water loss drilling fluid values in NaCl, CaCl.sub.2, and KCl brines as well as fresh water than has been found by any prior use of starch additive for water loss control, and at the same time maintain desirable flow characteristics and low shale sensitivity in the drilling fluid.
It is a further advantage that this invention is not pH sensitive and aids in solids control by inhibiting drill solids.
It is a further advantage of the present invention that, unlike other polymers on the market, it will tolerate large amounts of drill solids and yet remain a virtually non-damaging system because of its low water loss.
It is a further advantage of the present invention that water loss reduction is obtained with similarly low values for brines containing NaCl, CaCl.sub.2, KCl or mixtures thereof. Previously used additives have shown adequate water loss for one or two of the above brines but not all three as well as water. This is also advantageous economically since the same additive package may be used regardless of the constituents of water or brine being used at the drilling site.
These and other advantages and features will be apparent from the following discussion and description of the invention and several of the embodiments thereof.